Shale hydration inhibition agent and method of use

ABSTRACT

A water-base wellbore fluid for use in subterranean wells that penetrate through a subterranean formation containing a shale which swells in the presence of water. The well bore fluid includes, an aqueous based continuous phase, and a shale hydration inhibition agent. One illustrative shale hydration inhibition agent is preferably the reaction product of a hydrogenation reaction of the product of the reaction of an aromatic amine with an aldehyde, preferably formaldehyde. Alternatively the shale hydration inhibition agent may be the reaction product of a hydrogenation reaction of the product of the reaction of aniline and formaldehyde. In one illustrative embodiment, the shale hydration inhibition agent is selected from the class of compounds known as polycycloaliphatic amines. The shale hydration inhibition agent may be present in the form of a free-base or preferably in the form of an acid salt of the disclosed amine compounds. The shale hydration inhibition agent is present in sufficient concentration to substantially reduce the swelling of shale drilling cuttings upon contact with the fluid.

This is a continuation-in-part of co-pending U.S. patent applicationSer. No. 10/958,635 filed Oct. 5, 2004, to which priority is claimed andthe contents of which are hereby incorporated by reference.

BACKGROUND

In rotary drilling of subterranean wells numerous functions andcharacteristics are expected of a well bore fluid. A well bore fluidshould circulate throughout the well and carry cuttings from beneath thebit, transport the cuttings up the annulus, and allow their separationat the surface. At the same time, the well bore fluid is expected tocool and clean the drill bit, reduce friction between the drill stringand the sides of the hole, and maintain stability in the borehole'suncased sections. The well bore fluid should also form a thin, lowpermeability filter cake that seals openings in formations penetrated bythe bit and act to reduce the unwanted influx of formation fluids frompermeable rocks.

Well bore fluids are typically classified according to their basematerial. In oil base fluids, solid particles are suspended in oil, andwater or brine may be emulsified with the oil. The oil is typically thecontinuous phase. In water base fluids, solid particles are suspended inwater or brine, and oil may be emulsified in the water. The water istypically the continuous phase. Pneumatic fluids are a third class ofwell bore fluids in which a high velocity stream of air or natural gasremoves drill cuttings.

Three types of solids are usually found in water base well borefluids: 1) clays and organic colloids added to provide necessaryviscosity and filtration properties; 2) heavy minerals whose function isto increase the well bore fluid's density; and 3) formation solids thatbecome dispersed in the well bore fluid during the drilling operation.

The formation solids that become dispersed in a well bore fluid aretypically the cuttings produced by the drill bit's action and the solidsproduced by borehole instability. Where the formation solids are clayminerals that swell, the presence of either type of formation solids inthe well bore fluid can greatly increase drilling time and costs.

Clay minerals are generally crystalline in nature. The structure of aclay's crystals determines its properties. Typically, clays have aflaky, mica-type structure. Clay flakes are made up of a number ofcrystal platelets stacked face-to-face. Each platelet is called a unitlayer, and the surfaces of the unit layer are called basal surfaces.

A unit layer is composed of multiple sheets. One sheet is called theoctahedral sheet, it is composed of either aluminum or magnesium atomsoctahedrally coordinated with the oxygen atoms of hydroxyls. Anothersheet is called the tetrahedral sheet. The tetrahedral sheet consists ofsilicon atoms tetrahedrally coordinated with oxygen atoms.

Sheets within a unit layer link together by sharing oxygen atoms. Whenthis linking occurs between one octahedral and one tetrahedral sheet,one basal surface consists of exposed oxygen atoms while the other basalsurface has exposed hydroxyls. It is also quite common for twotetrahedral sheets to bond with one octahedral sheet by sharing oxygenatoms. The resulting structure, known as the Hoffman structure, has anoctahedral sheet that is sandwiched between the two tetrahedral sheets.As a result, both basal surfaces in a Hoffman structure are composed ofexposed oxygen atoms.

The unit layers stack together face-to-face and are held in place byweak attractive forces. The distance between corresponding planes inadjacent unit layers is called the c-spacing. A clay crystal structurewith a unit layer consisting of three sheets typically has a c-spacingof about 9.5×10−7 mm.

In clay mineral crystals, atoms having different valences commonly willbe positioned within the sheets of the structure to create a negativepotential at the crystal surface. In that case, a cation is adsorbed onthe surface. These adsorbed cations are called exchangeable cationsbecause they may chemically trade places with other cations when theclay crystal is suspended in water. In addition, ions may also beadsorbed on the clay crystal edges and exchange with other ions in thewater.

The type of substitutions occurring within the clay crystal structureand the exchangeable cations adsorbed on the crystal surface greatlyaffect clay swelling, a property of primary importance in the well borefluid industry. Clay swelling is a phenomenon in which water moleculessurround a clay crystal structure and position themselves to increasethe structure's c-spacing thus resulting in an increase in volume. Twotypes of swelling may occur.

Surface hydration is one type of swelling in which water molecules areadsorbed on crystal surfaces. Hydrogen bonding holds a layer of watermolecules to the oxygen atoms exposed on the crystal surfaces.Subsequent layers of water molecules align to form a quasi-crystallinestructure between unit layers, which results in an increased c-spacing.Virtually all types of clays swell in this manner.

Osmotic swelling is a second type of swelling. Where the concentrationof cations between unit layers in a clay mineral is higher than thecation concentration in the surrounding water, water is osmoticallydrawn between the unit layers and the c-spacing is increased. Osmoticswelling results in larger overall volume increases than surfacehydration. However, only certain clays, like sodium montmorillonite,swell in this manner.

Exchangeable cations found in clay minerals are reported to have asignificant impact on the amount of swelling that takes place. Theexchangeable cations compete with water molecules for the availablereactive sites in the clay structure. Generally cations with highvalences are more strongly adsorbed than ones with low valences. Thus,clays with low valence exchangeable cations will swell more than clayswhose exchangeable cations have high valences.

In the North Sea and the United States Gulf Coast, drillers commonlyencounter argillaceous sediments in which the predominant clay mineralis sodium montmorillonite (commonly called “gumbo shale”). Sodiumcations are predominately the exchangeable cations in gumbo shale. Asthe sodium cation has a low positive valence (i.e. formally a +1valence), it easily disperses into water. Consequently, gumbo shale isnotorious for its swelling.

Clay swelling during the drilling of a subterranean well can have atremendous adverse impact on drilling operations. The overall increasein bulk volume accompanying clay swelling impedes removal of cuttingsfrom beneath the drill bit, increases friction between the drill stringand the sides of the borehole, and inhibits formation of the thin filtercake that seals formations.

Clay swelling can also create other drilling problems such as loss ofcirculation or stuck pipe that slow drilling and increase drillingcosts. Thus, given the frequency in which gumbo shale is encountered indrilling subterranean wells, the development of a substance and methodfor reducing clay swelling remains a continuing challenge in the oil andgas exploration industry.

One method to reduce clay swelling is to use salts in well bore fluids.Salts generally reduce the swelling of clays. However, salts flocculatethe clays resulting in both high fluid losses and an almost completeloss of thixotropy.

Further, increasing salinity often decreases the functionalcharacteristics of well bore fluid additives.

Another method for controlling clay swelling is to use organic shaleinhibitor molecules in well bore fluids. It is believed that the organicshale inhibitor molecules are adsorbed on the surfaces of clays with theadded organic shale inhibitor competing with water molecules for clayreactive sites and thus serve to reduce clay swelling. One reportedshale inhibitor is the use of water soluble diamine compounds, such asprimary diamines with a chain length of 8 or less and primary alkylamines with a chain length of 4 or less. However, these amine compoundsare less desirable at higher temperatures and pressures. Further one ofskill in the art would understand that the amine compounds disclosedhave a low molecular weight and thus the ratio of hydrophilic tolipophilic portions of the molecule favors the hydrophilic amine moiety.Thus compounds having a greater carbon number are not desirable becauseof the lipophilic nature of the molecule.

In view of the above, one of skill in the art would appreciate andunderstand that there remains a continuing need for new shale hydrationinhibition agents within the art.

SUMMARY

Upon consideration of the present disclosure, one of skill in the artshould understand and appreciate that one illustrative embodiment of theclaimed subject matter includes a water-base wellbore fluid for use insubterranean wells that penetrate through a subterranean formationcontaining a shale which swells in the presence of water. In such anillustrative embodiment, the well bore fluid includes, an aqueous basedcontinuous phase, and a shale hydration inhibition agent. Oneillustrative shale hydration inhibition agent is preferably the reactionproduct of a hydrogenation reaction of the product of the reaction of anaromatic amine with an aldehyde, preferably formaldehyde. Alternativelythe shale hydration inhibition agent may be the reaction product of ahydrogenation reaction of the product of the reaction of aniline andformaldehyde. In one illustrative embodiment, the shale hydrationinhibition agent is selected from the class of compounds known aspolycycloaliphatic amines. Further the shale hydration inhibition agentmay be present in the form of a free-base or in the form of an acid saltof the disclosed amine compounds. The shale hydration inhibition agentis present in sufficient concentration to substantially reduce theswelling of shale drilling cuttings upon contact with the fluid.

The illustrative fluid is formulated such that it optionally includesviscosifying agents and/or weighting agents which should be well knownto one of skill in the art of formulating wellbore fluids. In additionthe aqueous based continuous phase may be selected from: fresh water,sea water, brine, mixtures of water and water soluble organic compoundsas well as mixtures and combinations of these and similar aqueous basedfluids that should be known to one of skill in the art. In oneillustrative embodiment, an optional viscosifying agent is included inthe fluid and the viscosifying agent is preferably selected frommixtures and combinations of compounds that should be known to one ofskill in the art such as xanthan gums, starches, modified starches andsynthetic viscosifiers such as polyacrylamides, and the like. Aweighting material such as barite, calcite, hematite, iron oxide,calcium carbonate, organic and inorganic salts, as well as mixtures andcombinations of these and similar compounds that should be known to oneof skill in the art may optionally be included into the formulation ofthe illustrative fluid. The illustrative fluid may also include a widevariety of conventional components of aqueous based well bore fluids,such as fluid loss control agents, suspending agents, viscosifyingagents, rheology control agents, as well as other compounds andmaterials that one of skill in the art would be knowledgeable about.

The scope of the claimed subject matter also encompasses a fracturingfluid for use in a subterranean well in which the subterranean wellpenetrates through one or more subterranean formation composed of shalethat swells in the presence of water. One illustrative fluid isformulated to include an aqueous based continuous phase, a viscosifyingagent and the shale hydration inhibition agents disclosed herein andwhich are present in sufficient concentration to substantially reducethe swelling of shale.

The scope of the claimed subject matter also encompasses water basedfluids which will form a semipermeable membrane over a shale formationto increase wellbore stability. This result is achieved by carefullyselecting the amine and then adjusting the pH or crosslinking with othercomponents resulting in a precipitation of the amine which then forms amembrane over the surface of the rock formation and thus stabilizing thewellbore.

It should also be appreciated that the claimed subject matter inherentlyincludes components such as: an aqueous based continuous phase; aswellable shale material; and a shale hydration inhibition agent assubstantially described herein, and present in sufficient concentrationto substantially reduce the swelling of the swellable shale material.Such a composition may be formed during the course of drilling asubterranean well, but also may be deliberately made if drill cuttingsreinjection is to be carried out.

One of skill in the art should appreciate that the fluids of the claimedsubject matter are useful during the course of the drilling, completing,cementing, fracturing, maintenance and production, workover, abandonmentof a well and other operations associated with subterranean wells. Theclaimed subject matter also includes a method of disposing of drillcuttings into a subterranean formation as part of a process well knownin the industry as cutting reinjection. It should also be appreciated byone of skill in the art that the claimed subject matter inherentlyincludes a method of reducing the swelling of shale clay in a well, themethod including circulating in the well a water-base well bore fluidformulated as is substantially disclosed herein. These and otherfeatures of the claimed subject matter are more fully set forth in thefollowing description of illustrative embodiments of the claimed subjectmatter.

DETAILED DESCRIPTION

The claimed subject matter is directed to a water-base well bore fluidfor use in subterranean wells that penetrate through a formationcontaining shale which swells in the presence of water. Generally thewell bore fluid of the claimed subject matter may be formulated toinclude an aqueous continuous phase and a shale hydration inhibitionagent, preferably an organic amine compound. As disclosed below, thewell bore fluids of the claimed subject matter may optionally includeadditional components, such as weighting agents, viscosity agents, fluidloss control agents, bridging agents, lubricants, anti-bit ballingagents, neutralizing agents, corrosion inhibition agents, alkali reservematerials and pH buffering agents, surfactants and suspending agents,rate of penetration enhancing agents, proppants, sand for gravelpacking, and other similar solids, and the like that one of skill in theart should understand may be added to an aqueous based well bore fluid.

The aqueous based continuous phase may generally be any water basedfluid phase that is compatible with the formulation of a well bore fluidand is compatible with the shale hydration inhibition agents disclosedherein. To solubilize the shale hydration inhibition agents disclosedherein, the amine functional group may require protonation prior to orduring drilling operations to make it functionally active.Alternatively, the shale hydration inhibition agent may derivatized bythe addition of polar organic functional groups, such as alkoxy,hydroxyl, carboxy or other functional groups that are known to enhancethe solubility of organic compounds in water. In one preferredembodiment, the aqueous based continuous phase is selected from: freshwater, sea water, brine, mixtures of water and water soluble organiccompounds and mixtures thereof. The amount of the aqueous basedcontinuous phase should be sufficient to form a water based well borefluid. This amount may range from nearly 100% of the well bore fluid toless than 1% of the well bore fluid by volume. Preferably, the aqueousbased continuous phase is from about 99% to about 20% by volume andpreferably from about 90 to about 40% by volume of the well bore fluid.

One of skill in the art of drilling fluid formulation should understandand appreciate that a shale hydration inhibition agent is included inthe formulation of the well bore fluids of the claimed subject matter sothat the hydration of shale, shale-like and clay containing formationsis inhibited. As the term is used herein, shale is intended to mean allshale, shale like and clay containing subterranean formations thatexhibit an undesirable reaction (such as swelling, disassociation,dispersion, etc . . . ) upon exposure to aqueous based fluids. Thus, theshale hydration inhibition agent should be present in sufficientconcentration to reduce either or both the surface hydration basedswelling and/or the osmotic based swelling of the shale/clay. The exactamount of the shale hydration inhibition agent present in a particularwell bore fluid formulation can be determined by a trial and errormethod of testing the combination of well bore fluid and arepresentative sample of formation encountered. Generally however, theshale hydration inhibition agent of the claimed subject matter may beused in well bore fluids in a concentration from about 0.5 to about 20pounds per barrel (lbs/bbl or ppb) and more preferably in aconcentration from about 2 to about 12 pounds per barrel of well borefluid.

As previously noted, the shale hydration inhibition agents of theclaimed subject matter are preferably lipophilic amine compounds. Thisis in contrast with many of the compounds of the prior art which arehydrophilic (i.e. at least partially soluble in water.). One of skill inthe art should note that some of the strongly lipophilic aminesdisclosed herein may be solubilized by the functionalization of one ormore amine groups. An example is the partial protonation of the aminefunctional group. Such protonation may be carried out by addition ofacid or by adjusting the pH of the well bore fluid to a predeterminedvalue. Alternatively, the shale hydration inhibition agents disclosedherein can be partially or fully protonated or neutralized prior totheir application in drilling operations. In place of protonation, theamine group may be functionalized by a small organic group containing1-3 carbon atoms. As a further alternative, the amine group may befunctionalized by use of organic groups that are easily hydrolyzed inthe downhole environment. For instance, amide, hydroxy amide, imine, orother such functionality may be introduced to affect the solubility ofthe shale hydration inhibition compounds disclosed herein.

In one illustrative embodiment, the shale hydration inhibition agent ofthe claimed subject matter should have the general formula:

in which R and R′ are independently selected from hydrogen, methyl,ethyl or propyl and X is a C5 to C12 bridging group and n is an integerfrom 1 to 8.

One illustrative amine that serves as a shale hydration inhibition agentis where X is a cyclohexyl group or other similar long chain orcycloalkyl or cycloaryl group. In such instances the amine may be aprimary, secondary or tertiary amine. For example cylcohexyl amine,N-methyl cyclohexyl amine and N,N-dimethyl cyclohexyl amine have allbeen found to be effective shale hydration inhibition agents. In thepresent illustrative embodiment, the shale hydration inhibition agentmay be in the free-base or acid salt form or some combination of thetwo.

In another illustrative shale hydration inhibition agent is preferablythe reaction product of a hydrogenation reaction of the product of thereaction of an aromatic amine with an aldehyde, preferably formaldehyde.Alternatively the shale hydration inhibition agent may be the reactionproduct of a hydrogenation reaction of the product of the reaction ofaniline and formaldehyde. In one illustrative embodiment, the shalehydration inhibition agent is selected from compounds having thegeneralized structure:

in which R and R′ independently selected from hydrogen, methyl, ethyl orpropyl, R″ is a bridging group having 1 to 20 carbon atoms and n has avalue from 1 to 4 and X is an amine, hydroxyl, alkoxy, carboxy group.The shale hydration agent may be present in the form of the free-base orthe acid salt of the base or some combination of the two. In onepreferred embodiment, the bridging group is selected from the aliphaticand aryl groups with or without additional functionality. Further itshould be noted that the amine group may be either in the ortho, meta orpara position relative to the bridging group, however, the para positionis preferred. Thus a preferred illustrative embodiment the shalehydration inhibition agent has the generalized formula:

in which in which R and R′ independently selected from hydrogen, methyl,ethyl or propyl, and X has a value from 1 to 6. The shale hydrationagent may be present in the form of the free-base or the acid salt ofthe base or some combination of the two.

A further illustrative embodiment of the shale hydration inhibitionagents of the claimed subject matter include compounds generally knownas mixed polycycloaliphatic amines (MPCA). MPCA is a commerciallyavailable mixture of compounds including aminoalkylcyclohexyl amines,aminoaralkylcyclohexyl amines and other such compounds. They are knownfor use in coatings, lube oil additives and corrosion inhibitors.Exemplary compounds that may be found in this mixture include compoundshaving the formula: Compound Structure A

B

C

D

E

F

G

The percent compositional ranges for the above exemplary constituents ofMPCA may vary considerably depending upon the source of the material. Inone illustrative embodiment the MPCA mixture contains the following:Compound Compositional Range (%) A 2-10 B 5-17 C 0.5-2   D 15-22  E33-50  F 8-20 G 3-8 

It is contemplated that from this mixture one or more compounds may befound to have an especially good ability to function as a shaleinhibition agent. One of skill in the art could make this determinationby simply purifying/isolating each compound and then testing the shaleinhibition properties of the isolated compound. Such routineexperimentation is well within the skill of one in the chemical arts andthus is considered to be within the scope of the present invention.

As shown in the above formulas, the illustrative shale hydrationinhibition agents are free base amines (i.e. unprotonated). One of skillin the art should appreciate that the shale hydration inhibition agentsof the claimed subject matter may be partially or fully protonateddepending upon the pH of the well bore fluid during or prior to use.Further it should be appreciated that the protonation state of the aminecan be easily adjusted during or prior to use by simply adjusting the pHof the well bore fluid. Illustrative examples of protic acids that mightbe useful include both mineral acids (i.e. hydrochloric, hydrobrmic,sulfuric, nitric, and other such acids) and organic acids (i.e.carboxylic acids, formic, acetic, propionic, butyric, citric,halogenated carboxylic acids, sulfonate and phosphonate organiccompounds, and other similar acids). In one preferred embodiment, simplecarboxylic acids are reacted with the shale inhibitors to increase thesolubility of the material in aqueous solutions. Other organic acidsthat function as chelating agents may be useful as well. For instance,ethylene diaminetetraacetate (EDTA), ethylenediaminetetraacetic acid(EDTA), cyclohexylene dinitrilo tetraacetic acid (CDTA),[ethylenebis(oxyethylenenitrilo)]tetraacetic acid (EGTA) and[[(carboxymethyl)imino]-bis(ethylenenitrilo)]-tetra-acetic acid,hydroxyethylethylenediaminetriacetic acid (HEDTA) andhydroxyethyliminodiacetic acid (HEIDA) as well as the mono cationic anddicationic salts of these compounds. It should be appreciated by one ofskill in the art that by routine trial and error a skilled person canselect an acid material utilized to neutralize the amine functionalgroups, and thus substantially affect the solubility of the shaleinhibition agents disclosed herein. Such concepts are within the scopeof the present disclosure. Thus in a generalized illustrativeembodiment, the shale hydration inhibition agents of the presentinvention may have the formula:(H+A)_(x)(A)_(y)xB⁻

in which A represents an amine functional group on the compoundsdisclosed herein, H⁺A represents a protonated amine functional group onthe shale hydration inhibition agents disclosed herein, x represents themolar equivalents of acid and x+y equals the number of amine functionalgroups present. One illustrative embodiment of such a compound includesthe reaction product of a predetermined amount of carboxylic acid,preferably formic, acetic or propionic acid and MPCA. The reactionproduct may be isolated as an amine salt, or the resulting solution maybe used directly in formulating the well bore fluids disclosed herein.Another illustrative embodiment the shale hydration inhibition agentshaving the formula:

in which R and R′ independently selected from hydrogen, methyl, ethyl orpropyl, R″ is a bridging group having 1 to 20 carbon atoms and n has avalue from 1 to 4 and X is an amine, hydroxyl, alkoxy, carboxy group, inwhich at least one of the amine functional groups have been reacted witha predetermined amount of C1 to C25 carboxylic acid. In one preferredembodiment, the bridging group is selected from the aliphatic and arylgroups with or without additional functionality. As with the free-basematerial, the amine group may be either in the ortho, meta or paraposition relative to the bridging group, however, the para position ispreferred.

The well bore fluids of the claimed subject matter can include a weightmaterial in order to increase the density of the fluid. The primarypurpose for such weighting materials is to increase the density of thewell bore fluid so as to prevent kick-backs and blow-outs. One of skillin the art should know and understand that the prevention of kick-backsand blow-outs is important to the safe day to day operations of adrilling rig. Thus the weight material is added to the well bore fluidin a functionally effective amount largely dependent on the nature ofthe formation being drilled. Weight materials suitable for use in theformulation of the well bore fluids of the claimed subject matter may begenerally selected from any type of weighting materials be it in solid,particulate form, suspended in solution, dissolved in the aqueous phaseas part of the preparation process or added afterward during drilling.It is preferred that the weight material be selected from the groupincluding barite, hematite, iron oxide, calcium carbonate, magnesiumcarbonate, organic and inorganic salts, and mixtures and combinations ofthese compounds and similar such weight materials that may be utilizedin the formulation of well bore fluids.

The well bore fluids of the claimed subject matter can include aviscosifying agent in order to alter or maintain the rheologicalproperties of the fluid. The primary purpose for such viscosifyingagents is to control the viscosity and potential changes in viscosity ofthe well bore fluid. Viscosity control is particularly important becauseoften a subterranean formation may have a temperature significantlyhigher than the surface temperature. Thus a well bore fluid may undergotemperature extremes of nearly freezing temperatures to nearly theboiling temperature of water or higher during the course of its transitfrom the surface to the drill bit and back. One of skill in the artshould know and understand that such changes in temperature can resultin significant changes in the rheological properties of fluids. Thus inorder to control and/or moderate the rheology changes, viscosity agentsand rheology control agents may be included in the formulation of thewell bore fluid. Viscosifying agents suitable for use in the formulationof the well bore fluids of the claimed subject matter may be generallyselected from any type of viscosifying agents suitable for use inaqueous based well bore fluids. In one illustrative embodiment, aviscosifying agent is included in the well bore fluid and theviscosifying agent is preferably selected mixtures and combinations ofcompounds that should be known to one of skill in the art such asxanthan gums, starches, modified starches and synthetic viscosifierssuch as polyacrylamides, and the like as well as organophilic bentonite,sepiolite, clay, and attapulgite clay.

In addition to the components noted above, the claimed well bore fluidsmay also be formulated to include materials generically referred to asalkali reserve and alkali buffering agent, pH buffering agents,thinners, and fluid loss control agents, as well as other compounds andmaterials which are optionally added to water base well bore fluidformulations. Of these additional materials, each can be added to theformulation in a concentration as Theologically and functionallyrequired by drilling conditions.

One of skill in the art should appreciate that lime is the common alkalireserve agent utilized in formulating water based well bore fluids.Alkali buffering agents, such as cyclic organic amines, stericallyhindered amines, amides of fatty acids and the like may also be includedto serve as a buffer against the loss of the alkali reserve agent. Thewell bore fluid may contain amine protonating or pH buffering agents tosolubilize the shale inhibition agents and thus increase their activity.The well bore fluid may also contain anticorrosion agents as well toprevent corrosion of the metal components of the drilling operationalequipment. Thinners such as lignosulfonates are also often added towater-base well bore fluids. Typically lignosulfonates, modifiedlignosulfonates, polyphosphates and tannins are added. In otherembodiments, low molecular weight polyacrylates can also be added asthinners. Thinners are added to a well bore fluid to reduce flowresistance and control gelation tendencies. Other functions performed bythinners include reducing filtration and filter cake thickness,counteracting the effects of salts, minimizing the effects of water onthe formations drilled, emulsifying oil in water, and stabilizing mudproperties at elevated temperatures.

A variety of fluid loss control agents may be added to the well borefluids of the claimed subject matter that are generally selected from agroup consisting of synthetic organic polymers, biopolymers, andmixtures thereof. The fluid loss control agents such as modifiedlignite, polymers, modified starches and modified celluloses may also beadded to the water base well bore fluid system of this invention. In oneembodiment it is preferred that the additives of the invention should beselected to have low toxicity and to be compatible with common anionicwell bore fluid additives such as polyanionic carboxymethylcellulose(PAC or CMC), polyacrylates, partially-hydrolyzed polyacrylamides(PHPA), lignosulfonates, xanthan gum, mixtures of these and the like.

The well bore fluid of the claimed subject matter may further contain anencapsulating agent generally selected from the group consisting ofsynthetic organic, inorganic and bio-polymers and mixtures thereof. Therole of the encapsulating agent is to absorb at multiple points alongthe chain onto the clay particles, thus binding the particles togetherand encapsulating the cuttings. These encapsulating agents help improvethe removal of cuttings with less dispersion of the cuttings into thewell bore fluids. The encapsulating agents may be anionic, cationic,amphoteric, or non-ionic in nature. In one illustrative embodiment, apartially hydrolyzed polyacrylamide with cationic character is utilizedas an encapsulating agent.

Other additives that could be present in the well bore fluids of theclaimed subject matter include products such as lubricants, penetrationrate enhancers, defoamers, fluid loss circulation materials, propants,sized sand, as well as other materials that do not have a substantialimpact on the shale hydration inhibition properties of the fluidsdisclosed herein. Such compounds should be known to one of ordinaryskill in the art of formulating aqueous based well bore fluids.

The following examples are included to demonstrate preferred embodimentsof the claimed subject matter. It should be appreciated by those ofskill in the art that the techniques disclosed in the examples whichfollow represent techniques discovered by the inventors to function wellin the practice of the claimed subject matter, and thus can beconsidered to constitute preferred modes for its practice. However,those of skill in the art should, in light of the present disclosure,appreciate that many changes can be made in the specific embodimentswhich are disclosed and still obtain a like or similar result withoutdeparting from the scope of the claimed subject matter.

Unless otherwise stated, all starting materials are commerciallyavailable and standard laboratory techniques and equipment are utilized.The tests were conducted in accordance with the procedures in APIBulletin RP 13B-2, 1990.

The following abbreviations are sometimes used in describing the resultsdiscussed in the examples:

“PV” is plastic viscosity (CPS) which is one variable used in thecalculation of viscosity characteristics of a well bore fluid.

“YP” is yield point (lbs/100 ft²)which is another variable used in thecalculation of viscosity characteristics of well bore fluids.

“GELS” (lbs/100 ft²)is a measure of the suspending characteristics andthe thixotropic properties of a well bore fluid.

“F/L” is API fluid loss and is a measure of fluid loss in milliliters ofwell bore fluid at 100 psi.

EXAMPLE 1

The following drilling muds are formulated to illustrate the claimedsubject matter Base Mud 1 2 Fresh Water 276 276 276 Duovis 1.0 1.0 1.0Unitrol 3.0 3.0 3.0 UltraCap 2.0 2.0 2.0 4,4′-diaminodicyclohexylmethane— 10.5 — Cyclohexylamine — — 10.5 Barite 201 201 201 pH Adjusted (AceticAcid) 9.4 9.4 9.4

In the above mud formulation the following commercially availablecompounds have been used in the formulation of the well bore fluid, butone of skill in the art should appreciate that other similar compoundsmay be used instead. UltraCap M-I SWACO, Houston TX UltraFree M-I SWACO,Houston TX Unitrol M-I SWACO, Houston TX Duo Vis Kelco Oil Field Group

The properties of the above muds as well as a base mud (i.e. a mud inwhich there is no shale hydration inhibition agent) are measured andgive the following exemplary data: Properties Viscosity (cps) at AmbientTemperature Base Mud 1 2 600 rpm 136 115 109 300 rpm 101 84 76 200 rpm85 74 63 100 rpm 58 48 43  6 rpm 16 13 12  3 rpm 11 10 10 Gels 10 sec.12 12 12 10 min. 16 14 13 PV 35 31 33 YP 66 53 43 API F/L 3.8 3.0 3.2

Dispersion tests are run with Oxford Clay cuttings by hot rolling 10 gof cuttings in a one-barrel equivalent of mud for 16 hours at 150□F.After hot rolling the remaining cuttings are screened using a 20 meshscreen and washed with 10% potassium chloride water, dried and weighedto obtain the percentage recovered. The results of this evaluation aregiven in the following Table and shows the improved shale inhibitionperformance of shale hydration inhibition agent of this invention. (%cuttings recovered) Base Mud 1 2 Oxford Clay 88 98 94

To further demonstrate the performance of the well bore fluidsformulated in accordance with the teachings of this invention, a testusing a bulk hardness tester is conducted. A BP Bulk Hardness Tester isa device designed to give an assessment of the hardness of shalecuttings exposed to well bore fluids, which in turn can be related tothe inhibiting properties of the well bore fluid being evaluated. Inthis test, shale cuttings are hot rolled in the test well bore fluid at150° F. for 16 hours. Shale cuttings are screened and then placed into aBP Bulk Hardness Tester. The equipment is closed and using a torquewrench the force used to extrude the cuttings through a plate with holesin it is recorded. Depending on the hydration state and hardness of thecuttings and the well bore fluid used, a plateau region in torque isreached as extrusion of the cuttings begins to take place.Alternatively, the torque may continue to rise which tends to occur withharder cutting samples. Therefore, the higher the torque numberobtained, the more inhibitive the well bore fluid system is considered.Illustrative data obtained using the three different mud formulationswith Oxford clay cuttings are given below. Bulk Hardness: (values ininch/lbs) Oxford Clay Mud Formulation Turn No. Base Mud 1 2 3 — 5 — 4 —10 5 5 5 15 5 6 5 30 10 7 10 50 15 8 10 95 40 9 10 190 100 10 10 225 12011 10 D 135 12 15 150 13 15 165 14 15 170 15 15 190 16 15 200 17 20 22518 25 R, D 19 225 R

In the above table, D indicates formation of a disk; R indicates theformation of spaghetti like ribbons.

Upon review of the above data, one skilled in the art should observethat well bore fluids formulated according to the teachings of thisinvention prevent the hydration of various types of shale clays and thusare likely to provide good performance in drilling subterranean wellsencountering such shale clays.

EXAMPLE 2

The following testing was conducted to demonstrate the maximum amount ofAPI bentonite that can be inhibited by a single 10.5 ppb treatment ofshale hydration inhibition agents of the claimed subject matter over aperiod of days. This test procedure uses pint jars that are filed withone barrel equivalent of tap water and 10.5 ppb of a shale hydrationinhibition agent. Tap water was used as a control sample. All sampleswere adjusted to at least a pH of 9.5 with hydrochloric acid and treatedwith a 10 ppb portion of M-I GEL (API bentonite) at a medium sheer rate.After stirring for 30 minutes, the samples were heat aged overnight at150 □F. After the samples were cooled, their rhelologies were recordedat ambient temperature. This procedure was carried out for each sampleuntil all were too thick to measure. The tables below presentrepresentative data that shows the shale hydration inhibition effect ofthe claimed subject matters by the daily addition of bentonite in tapwater treated with the shale hydration inhibition agents indicated atthe top of each column. For purposes of the following example, thefollowing shale hydration inhibition agents are utilized: Additive CodeChemical A 4,4′-diaminodicyclohexylmethane B Cylcohexylamine (CHA) CN-methyl cyclohexylamine D N,N-dimethyl cyclohexylamine

600 rpm Rheology Data (centipoises) Bentonite (llb/bbl) Base KCl CholineChloride A B C D 50 TTTM 20 3 6 7 6 8 70 170 24 9 12 8 10 90 TTTM 85 1214 13 14 110 TTTM 17 18 21 25 130 27 29 29 35 150 47 47 36 48 170 67 5471 113 190 139 102 97 143 200 165 123 103 250 210 254 160 109 TTTM 220TTTM 201 157 230 TTTM 277 240 TTTM

In the above table the abbreviation TTTM means too thick to measure. 6rpm Rheology Data (centipoises) Bentonite (llb/bbl) Base KCl CholineChloride A B C D 50 TTTM 12 3 1 1 1 2 70 140 13 2 2 2 2 90 TTTM 32 2 2 23 110 TTTM 3 5 4 6 130 7 8 8 9 150 19 13 12 17 170 21 18 17 34 190 46 3224 36 200 53 36 25 41 210 77 47 26 131 220 TTTM 60 47 TTTM 230 161 98240 TTTM TTTM

In the above table the abbreviation TTTM means too thick to measure.Bentonite (llb/bbl) Base KCl Choline Chloride A B C D 50 TTTM 24 2 2 2 22 70 297 9 2 2 3 3 90 TTTM 31 2 3 3 3 110 TTTM 6 5 4 5 130 7 6 8 9 15013 10 8 14 170 18 14 12 23 190 39 25 18 34 200 52 31 25 83 210 86 37 28129 220 TTTM 62 47 TTTM 230 168 119 240 TTTM TTTM

In the above table the abbreviation TTTM means too thick to measure.Plastic Viscosity Bentonite (llb/bbl) Base KCl Choline Chloride A B C D50 TTTM 7 3 3 4 3 4 70 20 5 4 6 3 4 90 TTTM 20 5 5 5 6 110 TTTM 6 6 8 8130 10 10 9 8 150 12 17 8 9 170 12 14 16 17 190 21 25 20 45 200 30 32 2750 210 56 44 33 TTTM 220 TTTM 53 53 230 TTTM 55 240 TTTM

In the above table the abbreviation TTTM means too thick to measure.Yeild Point Bentonite (llb/bbl) Base KCl Choline Chloride A B C D 50TTTM 8 4 0 0 0 0 70 132 12 1 0 2 2 90 TTTM 65 2 4 3 2 110 TTTM 5 6 5 9130 7 7 11 19 150 23 17 20 30 170 43 26 39 79 190 97 52 57 53 200 105 5951 59 210 142 72 40 TTTM 220 TTTM 95 51 230 TTTM 167 240 TTTM

In the above table the abbreviation TTTM means too thick to measure.

Upon review of the above representative data, one of skill in the artshould observe that well bore fluids formulated according to theteachings of the disclosure substantially inhibit the hydration ofvarious shale clays and thus are likely to provide good performance indrilling subterranean wells encountering such shale clays.

Example 3

In this example, 3% by weight of 4,4′-dimethyldicyclohexylmethane wasdissolved into 1.5% glacial acetic acid solution in distilled water. Aclear solution formed upon stirring the mixture. To this resultingsolution a sufficient amount of 1.0 N sodium hydroxide was added tobring the pH to about 10.5. A white precipitate formed at this pH. Theprecipitate could be redissolved upon adjusting the pH to about 9.5.

The above example illustrates that a preferred shale hydrationinhibition agent of the present disclosure can be precipitated out ofsolution and onto shale surfaces by adjusting the pH. One of skill inthe art should appreciate that the ability to form this precipitate willprompt the formation of a membrane that should enhance well stability.

Example 4

The following testing was conducted to demonstrate the maximum amount ofAPI bentonite that can be inhibited by a single 10.5 ppb treatment ofshale hydration inhibition agents of the claimed subject matter over aperiod of days. This test procedure uses pint jars that are filed withone barrel equivalent of tap water and 10.5 ppb of a shale hydrationinhibition agent. Tap water was used as a control sample. All sampleswere adjusted to at least a pH of 9.5 with hydrochloric acid and treatedwith a 10 ppb portion of M-I GEL (API bentonite) at a medium sheer rate.After stirring for 30 minutes, the samples were heat aged overnight at150° F. After the samples were cooled, their rhelologies were recordedat ambient temperature. This procedure was carried out for each sampleuntil all were too thick to measure. The tables below presentrepresentative data that shows the shale hydration inhibition effect ofthe claimed subject matters by the daily addition of bentonite in tapwater treated with the shale hydration inhibition agents indicated atthe top of each column. In the present example 10.5 ppb of MPCA was usedto inhibit the total amount of bentonite. MPCA was neutralized with HCl,according to procedure described in Example 2 of this invention.

The following tables present exemplary results comparing the shalehydration inhibition performance of MPCA with potassium chloride andcholine chloride: 600 rpm Rheology Data (centipoises) MPCA BentoniteCholine Neutralized (lbs/bbl) Base KCl Chloride (pH 9.5) 50 TTTM 20 3 770 170 24 10 90 TTTM 85 17 110 TTTM 40 130 64 150 161 160 173 170 197180 TTTMIn the above tables the abbreviation TTTM means too thick to measure.

10 min gel MPCA Bentonite Choline Neutralized (lbs/bbl) Base KClChloride (pH 9.5) 50 TTTM 24 2 2 70 297 9 4 90 TTTM 31 6 110 TTTM 13 13025 150 55 160 89 170 157 180 TTTMIn the above tables the abbreviation TTTM means too thick to measure.

Plastic Viscosity MPCA Bentonite Choline Neutralized (lbs/bbl) Base KClChloride (pH 9.5) 50 TTTM 7 3 3 70 20 5 4 90 TTTM 20 5 110 TTTM 8 130 12150 19 160 16 170 43 180 TTTMIn the above tables the abbreviation TTTM means too thick to measure.

Yield Point MPCA Bentonite Choline Neutralized (lbs/bbl) Base KClChloride (pH 9.5) 50 TTTM 8 4 1 70 132 12 2 90 TTTM 65 7 110 TTTM 24 13040 150 123 160 141 170 111 180 TTTMIn the above tables the abbreviation TTTM means too thick to measure.

In the above tables the abbreviation TTTM means too thick to measure.

Upon review of the above representative data, one of skill in the artshould observe that well bore fluids formulated according to theteachings of the disclosure substantially inhibit the hydration ofvarious shale clays and thus are likely to provide good performance indrilling subterranean wells encountering such shale clays.

In view of the above disclosure, one of skill in the art shouldunderstand and appreciate that one illustrative embodiment of theclaimed subject matter includes a water-base wellbore fluid for use in asubterranean well that penetrates through one or more subterraneanformations containing a shale which swells in the presence of water. Thefluid is formulated to include an aqueous based continuous phase and ashale hydration inhibition agent which is a mixed polycycloaliphaticamine. The shale hydration inhibition agent is present in sufficientconcentration to reduce the swelling of shale. In one preferredillustrative embodiment, the shale hydration inhibition agent is thereaction product of a hydrogenation reaction of the product of thereaction of an aromatic amine with formaldehyde. Alternatively, theshale hydration inhibition agent is mixture ofaminoalkylcyclohexylanimes and aminoarylcyclohexylamines. In oneillustrative embodiment, at least one of the amine functionality groupsis functionalized, preferably protonated. The aqueous based continuousphase utilized in the illustrative embodiment is preferably selectedfrom fresh water, sea water, brine, and water soluble organic compoundsand mixtures thereof and similar fluids known to one of skill in theart. Conventional additives for wellbore fluids may also be added to theillustrative embodiment including viscosifying agents, rheology controlagents, corrosion control agents, weighting agents as well ascombinations of these and similar compounds that should be well known toone of skill in the art. In most instances, a weighting material isdesired to increase the density of the fluid. Such illustrativeweighting agents may be soluble or insoluble in water. In oneillustrative embodiment, the weighting agent is selected from the groupconsisting of barite, calcite, hematite, iron oxide, calcium carbonate,organic and inorganic salts, and mixtures thereof as well as similarcompounds that should be well known to one of skill in the art.

Another illustrative embodiment of the claimed invention includes awater- base fluid for use in drilling or completing a subterranean wellthrough one or more subterranean formations containing a shale whichswells in the presence of water, in which the well bore fluid includes:an aqueous based continuous phase a weighting agent; and a shalehydration inhibition agent which includes a mixed polycycloaliphaticamine. The illustrative formulation is such that the shale hydrationinhibition agent is present in sufficient concentration to reduce theswelling of shale. In one preferred illustrative embodiment, the shalehydration inhibition agent is the reaction product of a hydrogenationreaction of the product of the reaction of an aromatic amine withformaldehyde. Alternatively, the shale hydration inhibition agent ismixture of aminoalkylcyclohexylanimes and aminoarylcyclohexylamines. Inone illustrative embodiment, at least one of the amine functionalitygroups is functionalized, preferably protonated. The aqueous basedcontinuous phase utilized in the illustrative embodiment is preferablyselected from fresh water, sea water, brine, and water soluble organiccompounds and mixtures thereof and similar fluids known to one of skillin the art.

Conventional additives for wellbore fluids may also be added to theillustrative embodiment including viscosifying agents, rheology controlagents, corrosion control agents, weighting agents as well ascombinations of these and similar compounds that should be well known toone of skill in the art. In most instances, a weighting material isdesired to increase the density of the fluid.

Such illustrative weighting agents may be soluble or insoluble in water.In one illustrative embodiment, the weighting agent is selected from thegroup consisting of barite, calcite, hematite, iron oxide, calciumcarbonate, organic and inorganic salts, and mixtures thereof as well assimilar compounds that should be well known to one of skill in the art.

A further illustrative embodiment of the claimed subject matter includesa water-base well bore fluid that is formulated to include an aqueousbased continuous phase; a weighting agent; and a shale hydrationinhibition agent having the formula:

in which R and R′ independently selected from hydrogen, methyl, ethyl orpropyl, R″ is a bridging group having 1 to 20 carbon atoms and n has avalue from 1 to 4 and X is an amine, hydroxyl, alkoxy, carboxy group.The illustrative shale hydration inhibition agent is present insufficient concentration to reduce the swelling of shale. In onepreferred illustrative embodiment, the shale hydration inhibition agentis the reaction product of a hydrogenation reaction of the product ofthe reaction of an aromatic amine with formaldehyde. Alternatively, theshale hydration inhibition agent is mixture ofaminoalkylcyclohexylanimes and aminoarylcyclohexylamines. In oneillustrative embodiment, at least one of the amine functionality groupsis functionalized, preferably protonated. The aqueous based continuousphase utilized in the illustrative embodiment is preferably selectedfrom fresh water, sea water, brine, and water soluble organic compoundsand mixtures thereof and similar fluids known to one of skill in theart. Conventional additives for wellbore fluids may also be added to theillustrative embodiment including viscosifying agents, rheology controlagents, corrosion control agents, weighting agents as well ascombinations of these and similar compounds that should be well known toone of skill in the art. In most instances, a weighting material isdesired to increase the density of the fluid. Such illustrativeweighting agents may be soluble or insoluble in water. In oneillustrative embodiment, the weighting agent is selected from the groupconsisting of barite, calcite, hematite, iron oxide, calcium carbonate,organic and inorganic salts, and mixtures thereof as well as similarcompounds that should be well known to one of skill in the art.

One of skill in the art should further appreciate that the free-baseamine shale hydration inhibition agent of the present disclosure mayalso be utilized as acid salts of the amine. Thus in one illustrativeembodiment, there is a water- base wellbore fluid for use in asubterranean well penetrating through one or more subterraneanformations containing a shale which swells in the presence of water, inwhich the fluid is formulated to include: an aqueous based continuousphase; a viscosifying agent; and a shale hydration inhibition agentwhich is an acid salt of a polycycloaliphatic amine. As with the freebase systems the shale hydration inhibition agent is present insufficient concentration to reduce the swelling of shale. In oneillustrative embodiment, the shale hydration inhibition agent is an acidsalt of the reaction product of a hydrogenation reaction of the productof the reaction of an aromatic amine with formaldehyde. Alternatively,the shale hydration inhibition agent may be a mixture of compoundsselected from the group consisting of: a free-baseaminoalkylcyclohexylamine; a free-base aminoarylcyclohexylamine; an acidsalt of aminoalkylcyclohexylamine; an acid salt ofaminoarylcyclohexylamine and combinations thereof as well as similarsuch compounds as should be known to one of skill in the art. In formingthe acid salt, the acid utilized in one illustrative embodiment isselected from the group consisting of mineral acids, organic acids andcombinations thereof. Preferably, the acid utilized to form the acidsalt is a C1 to C25 carboxylic acid. As noted above, one of skill in theart should appreciate that by forming the acid salt of the aminefunctional group, the solubility of the shale hydration inhibition agentin aqueous solutions will be measurably enhanced.

The aqueous based continuous phase utilized in the illustrativeembodiment is preferably selected from fresh water, sea water, brine,and water soluble organic compounds and mixtures thereof and similarfluids known to one of skill in the art. Conventional additives forwellbore fluids may also be added to the illustrative embodimentincluding viscosifying agents, rheology control agents, corrosioncontrol agents, weighting agents as well as combinations of these andsimilar compounds that should be well known to one of skill in the art.In most instances, a weighting material is desired to increase thedensity of the fluid. Such illustrative weighting agents may be solubleor insoluble in water. In one illustrative embodiment, the weightingagent is selected from the group consisting of barite, calcite,hematite, iron oxide, calcium carbonate, organic and inorganic salts,and mixtures thereof as well as similar compounds that should be wellknown to one of skill in the art. When a viscosifying agent is utilizedin the formulation of the illustrative fluid, it preferably may beselected from natural and synthetic polymers, and organophilic clay andcombinations thereof as well as other viscosifying agents that should bewell known to one of skill in the art of well bore fluids.

Alternatively, one illustrative embodiment for the disclosed water-basefluids includes: an aqueous based continuous phase; a weighting agent;and a shale hydration inhibition agent which includes an acid salt of amixed polycycloaliphatic amine. As with the free base systems the shalehydration inhibition agent is present in sufficient concentration toreduce the swelling of shale. In one illustrative embodiment, the shalehydration inhibition agent is an acid salt of the reaction product of ahydrogenation reaction of the product of the reaction of an aromaticamine with formaldehyde. Alternatively, the shale hydration inhibitionagent may be a mixture of compounds selected from the group consistingof: a free-base aminoalkylcyclohexylamine; a free-baseaminoarylcyclohexylamine; an acid salt of aminoalkylcyclohexylamine; anacid salt of aminoarylcyclohexylamine and combinations thereof as wellas similar such compounds as should be known to one of skill in the art.In forming the acid salt, the acid utilized in one illustrativeembodiment is selected from the group consisting of mineral acids,organic acids and combinations thereof. Preferably, the acid utilized toform the acid salt is a C1 to C25 carboxylic acid. As noted above, oneof skill in the art should appreciate that by forming the acid salt ofthe amine functional group, the solubility of the shale hydrationinhibition agent in aqueous solutions will be measurably enhanced.

The aqueous based continuous phase utilized in the illustrativeembodiment is preferably selected from fresh water, sea water, brine,and water soluble organic compounds and mixtures thereof and similarfluids known to one of skill in the art. Conventional additives forwellbore fluids may also be added to the illustrative embodimentincluding viscosifying agents, rheology control agents, corrosioncontrol agents, weighting agents as well as combinations of these andsimilar compounds that should be well known to one of skill in the art.In most instances, a weighting material is desired to increase thedensity of the fluid. Such illustrative weighting agents may be solubleor insoluble in water. In one illustrative embodiment, the weightingagent is selected from the group consisting of barite, calcite,hematite, iron oxide, calcium carbonate, organic and inorganic salts,and mixtures thereof as well as similar compounds that should be wellknown to one of skill in the art. When a viscosifying agent is utilizedin the formulation of the illustrative fluid, it preferably may beselected from natural and synthetic polymers, and organophilic clay andcombinations thereof as well as other viscosifying agents that should bewell known to one of skill in the art of well bore fluids.

In a further illustrative embodiment of the water-base well bore fluidsdisclosed herein, the fluid is formulated to include: an aqueous basedcontinuous phase; a weighting agent; and a shale hydration inhibitionagent having the formula:

in which R and R′ independently selected from hydrogen, methyl, ethyl orpropyl, R″ is a bridging group having 1 to 20 carbon atoms and n has avalue from 1 to 4 and X is an amine, hydroxyl, alkoxy, carboxy group, inwhich at least one of the amine functional groups have been reacted witha predetermined amount of C1 to C25 carboxylic acid. As with the freebase systems the shale hydration inhibition agent is present insufficient concentration to reduce the swelling of shale.

The aqueous based continuous phase utilized in the illustrativeembodiment is preferably selected from fresh water, sea water, brine,and water soluble organic compounds and mixtures thereof and similarfluids known to one of skill in the art. Conventional additives forwellbore fluids may also be added to the illustrative embodimentincluding viscosifying agents, rheology control agents, corrosioncontrol agents, weighting agents as well as combinations of these andsimilar compounds that should be well known to one of skill in the art.In most instances, a weighting material is desired to increase thedensity of the fluid. Such illustrative weighting agents may be solubleor insoluble in water. In one illustrative embodiment, the weightingagent is selected from the group consisting of barite, calcite,hematite, iron oxide, calcium carbonate, organic and inorganic salts,and mixtures thereof as well as similar compounds that should be wellknown to one of skill in the art. When a viscosifying agent is utilizedin the formulation of the illustrative fluid, it preferably may beselected from natural and synthetic polymers, and organophilic clay andcombinations thereof as well as other viscosifying agents that should bewell known to one of skill in the art of well bore fluids.

It should be appreciated that the use of the fluids disclosed herein isalso within the scope of the contemplated invention. Thus oneillustrative embodiment includes a method of disposing of drill cuttingsinto a subterranean formation utilizing the fluids disclosed herein. Inone such method, the process includes: grinding the drill cuttings in awater-base fluid to form a slurry, in which the water based fluidincludes: an aqueous based continuous phase and a shale hydrationinhibition agent which includes an acid salt or free-base of a mixedpolycycloaliphatic amine. The shale hydration inhibition agent shouldpresent in sufficient concentration to reduce the swelling of shale. Theslurry thus formed is injected into the subterranean formation fordisposal purposes.

Further it should be appreciated that the disclosed subject matterincludes methods for utilizing the disclosed fluids in the drilling andcompletion of a subterranean well. Thus, one illustrative embodiment ofthe claimed subject matter includes: conducting drilling or completingoperations in a subterranean well that penetrates through one or moresubterranean formations containing a shale which swells in the presenceof water, wherein the conduct is carried out in the presence of a wellbore fluid, wherein the well bore fluid includes: an aqueous basedcontinuous phase; and a shale hydration inhibition agent which includesthe acid salt or free-base form of a mixed polycycloaliphatic amine. Theshale hydration inhibition agent is present in sufficient concentrationto reduce the swelling of shale encountered in the operation.

While the compositions and methods of this claimed subject matter havebeen described in terms of preferred embodiments, it will be apparent tothose of skill in the art that variations may be applied to the processdescribed herein without departing from the concept and scope of theclaimed subject matter. All such similar substitutes and modificationsapparent to those skilled in the art are deemed to be within the scopeand concept of the claimed subject matter as it is set out in thefollowing claims.

1. A water-base wellbore fluid for use in a subterranean wellpenetrating through one or more subterranean formations containing ashale which swells in the presence of water, wherein the fluidcomprises: an aqueous based continuous phase; a viscosifying agent; anda shale hydration inhibition agent which is an acid salt of apolycycloaliphatic amine; and wherein the shale hydration inhibitionagent is present in sufficient concentration to reduce the swelling ofshale.
 2. The water-base well bore fluid of claim 1 wherein the shalehydration inhibition agent is an acid salt of the reaction product of ahydrogenation reaction of the product of the reaction of an aromaticamine with formaldehyde
 3. The water-base well bore fluid of claim 1wherein the shale hydration inhibition agent is mixture of compoundsselected from the group consisting of: a free-baseaminoalkylcyclohexylamine; a free-base aminoarylcyclohexylamine; an acidsalt of aminoalkylcyclohexylamine; an acid salt ofaminoarylcyclohexylamine and combinations thereof.
 4. The water-basewell bore fluid of claim 1 wherein the aqueous based continuous phase isselected from: fresh water, sea water, brine, and water soluble organiccompounds and mixtures thereof.
 5. The water-base well bore fluid ofclaim 1 wherein viscosifying agent is selected from natural andsynthetic polymers, and organophillic clay and combinations thereof. 6.The water-base well bore fluid of claim 5 further comprising a weightingmaterial selected from the group consisting of barite, calcite,hematite, iron oxide, calcium carbonate, organic and inorganic salts,and mixtures thereof.
 7. The water-base well bore fluid of claim 1wherein the acid utilized to form the acid salt is selected from thegroup consisting of mineral acids, organic acids and combinationsthereof.
 8. The water base well bore fluid of claim 1 wherein the acidutilized to form the acid salt is a C1 to C25 carboxylic acid.
 9. Awater-base fluid for use in drilling or completing a subterranean wellthrough one or more subterranean formations containing a shale whichswells in the presence of water, the well bore fluid comprising: anaqueous based continuous phase; a weighting agent; and a shale hydrationinhibition agent which includes an acid salt of a mixedpolycycloaliphatic amine; and wherein the shale hydration inhibitionagent is present in sufficient concentration to reduce the swelling ofshale.
 10. The water-base well bore fluid of claim 9 wherein the shalehydration inhibition agent is the acid salt of the reaction product of ahydrogenation reaction of the product of the reaction of an aromaticamine with formaldehyde
 11. The water-base well bore fluid of claim 9wherein the shale hydration inhibition agent is mixture of a free-baseaminoalkylcyclohexylamine; a free-base aminoarylcyclohexylamine; an acidsalt of aminoalkylcyclohexylamine; an acid salt ofaminoarylcyclohexylamine and combinations thereof.
 12. The water-basewell bore fluid of claim 9 wherein the aqueous based continuous phase isselected from: fresh water, sea water, brine, and water soluble organiccompounds and mixtures thereof.
 13. The water-base well bore fluid ofclaim 9 further comprising a viscosifying agent.
 14. The water-base wellbore fluid of claim 13 wherein the weighting material is selected fromthe group consisting of barite, calcite, hematite, iron oxide, calciumcarbonate, organic and inorganic salts, and mixtures thereof.
 15. Thewater-base well bore fluid of claim 9 wherein the acid utilized to formthe acid salt is selected from the group consisting of mineral acids,organic acids and combinations thereof.
 16. The water base well borefluid of claim 9 wherein the acid utilized to form the acid salt is a C1to C25 carboxylic acid.
 17. A water-base well bore fluid for use in asubterranean well penetrating through one or more subterraneanformations containing a shale which swells in the presence of water,wherein the fluid comprises: an aqueous based continuous phase; aweighting agent; and a shale hydration inhibition agent having theformula:

in which R and R′ independently selected from hydrogen, methyl, ethyl orpropyl, R″ is a bridging group having 1 to 20 carbon atoms and n has avalue from 1 to 4 and X is an amine, hydroxyl, alkoxy, carboxy group, inwhich at least one of the amine functional groups have been reacted witha predetermined amount of C1 to C25 carboxylic acid; and wherein theshale hydration inhibition agent is present in sufficient concentrationto reduce the swelling of shale.
 18. The water-base well bore fluid ofclaim 17 wherein the weighting material is selected from the groupconsisting of barite, calcite, hematite, iron oxide, calcium carbonate,organic and inorganic salts, and mixtures thereof.
 19. The water-basewell bore fluid of claim 17 wherein the acid utilized to form the acidsalt is selected from the group consisting of mineral acids, organicacids and combinations thereof.
 20. The water base well bore fluid ofclaim 17 wherein the acid utilized to form the acid salt is a C1 to C25carboxylic acid.